The success of well treatment operations often depends on optimizing placement of fluids downhole. This is especially the case for fluids used in acid stimulation, hydraulic fracturing, sand control, well clean-out and well completion operations. It further is true for treatment operations which employ fluid loss pills.
In the past, much interest has focused on methods for improving downhole placement of well treatment fluids used in acid stimulation and hydraulic fracturing operations. Acid simulation of a hydrocarbon formation, such as by matrix acidizing, enhances the production of hydrocarbons within the formation. In this procedure, acid or an acid-forming material is injected into the formation and the acid reacts with minerals in the formation. As a result, near-wellbore permeability is improved by the opening of channels or wormholes within the formation. In addition to dissolving formation materials, the acid may remove blockages caused by natural or man-made conditions. The procedure is especially prevalent in the treatment of carbonate formations since the reaction products are soluble in the spent acid.
Early attempts at optimizing the placement of acid downhole focused on injection of a simple acidic solution into the wellbore. Such attempts proved to be inefficient as the fluid often reacted or was spent too quickly. Such treatment fluids were therefore incapable of penetrating deep into the formation, thereby limiting their effectiveness to very near-wellbore applications. Thus, where the treated subterranean formation contained sections with varying permeability, the injected acid typically acidized the zone within the formation which had the highest permeability and the highest degree of water saturation. A permeability contrast between areas of high permeability (treated areas) within the formation and areas of low permeability (untreated areas) resulted.
It is necessary that acid placement downhole be optimized in order to provide uniform distribution of treatment fluid over the zone being treated. Chemical, as well as mechanical, methods have been developed in order to divert the flow of treatment fluids from the higher permeability and/or water saturated sections of the formation to the lower permeability or oil bearing sections. The difference between chemical and mechanical diversion is that chemical diverting agents achieve diversion by increasing flow resistance inside the created channels, whereas mechanical diversion controls the fluid entry point at the wellbore. Hence chemical diverting agents are often considered to be internal diverting agents compared to external mechanical diversion.
In the past, chemical diversion has been achieved by the use of viscous fluids, foams and gels which reportedly improve acid placement. Though several chemical diverters have emerged over the years, they have each failed to precisely control the flow of the acidizing fluid. One such alternative, disclosed in U.S. Pat. No. 7,060,661 is drawn to the use of a single surfactant system as a gelled acidizing fluid wherein the surfactant gels an acid fluid containing between 3 to 15% HCl solution by volume. Extra energy is often required to pump this already viscous gelled fluid into the well.
Further, N,N,-bis (2-hydroxyethyl) tallow ammonium acetate has been proposed as a gelling agent though the compound exhibits breakdown at higher temperatures as the acid is spent. In addition, since the compound gels too quickly, it is unable to fully penetrate into the formation. In addition, the maximum viscosity of the gelling agent is too low to adequately perform the necessary diverting.
Other proposed alternatives employ crosslinked systems wherein a gel is produced from a polymerization reaction while the fluid is pumped into the formation. A residue is often left in the formation which causes damage to the formation. Such systems are further dependent upon a sensitive chemical reaction since it is desirable that polymerization be delayed during pumping and maximized once the fluid is within the formation. Further, breakers for defragmenting the crosslinked polymer are typically needed to remove such systems from the well.
Other attempts at creating a gelled acidizing fluid have used a multi-surfactant based system. An example of this type of system was described in U.S. Pat. No. 6,399,546. These systems are often undesirable because they require mixing of two or more compounds at the well site. In addition, the ratio of the components is often dependent on the temperature and the pH of the system. Further, gelling of the system often requires introduction of a chemical trigger.
More recently, improvements have been seen with in-situ gelled acids. For instance, U.S. Pat. No. 7,303,018 discloses a gelled or thickened viscoelastic foam or fluid generated from (i.) an amidoamine oxide gelling agent and (ii.) an acid, water and/or brine, optionally mixed with a gas to form a foam. In-situ gelled acids offer the benefit of increased viscosity inside the formation. Thus, when acid first enters the high permeability zone and generates wormholes, its viscosity becomes higher than the acid still in the wellbore. This provides extra resistance in the already treated high permeability region or in the wormholes and increases the likelihood that the acid will enter the low permeability untreated zones of the formation.
Oil-soluble naphthalenes, crushed limestone, sodium tetraborate, oyster shells, gilsonite, perilite and paraformaldehyde have also been reported for use as chemical diverters. Such materials have been shown to be only useful in reservoirs having a bottom hole temperature of 175° F. or less. Interest in these compounds has been replaced by rock salt, which is partially soluble in the acid, inexpensive and easier to handle.
In addition to rock salt, diversion techniques have also focused on materials which are completely acid soluble. For instance, wax-polymer blends and hydrocarbon resins have been used in production wells and benzoic acid in water-injection wells. Most oil-soluble resins are not useful, however, for acidizing in carbonates because such resins are unable to bridge the large flow spaces created by the reaction of the injected acid with the reservoir rock. Recently, solid organic acid flakes, such as lactic acid flakes, have been reported to be useful for acid diversion. Such materials can only be used in wells with bottom hole temperatures below 250° F. In addition, while such materials hydrolyze to release acid, a high volume of water is required to completely hydrolyze the material and to ensure full conversion of the solid materials into acid. Failure to remove the solids causes formation damage.
A need exists therefore for a chemical diverter that does not rely upon crosslinking for gelation and which exhibits high viscosity. Such diverters need to adequately divert incoming fluids and yet allow maximum penetration. In particular, the diverter should be capable of being useful at bottom hole temperatures in excess of 175° F. and in most cases in excess of 250° F.
It further would be helpful for the diverting agent to have applications in other well treatment operations such as in hydraulic fracturing, sand control, well clean-out and well completion operations.